Oil sand production without co2 emission

ABSTRACT

A plant for generation of steam for oil sand recovery from carbonaceous fuel with capture of CO 2  from the exhaust gas, comprising heat coils ( 105, 105′, 105″ ) arranged in a combustion chamber ( 101 ) to cool the combustion gases in the combustion chamber to produce steam and superheated steam in the heat coils, steam withdrawal lines ( 133, 136, 145 ) for withdrawing steam from the heat coils, an exhaust gas line ( 106 ) for withdrawal of exhaust gas from the combustion chamber ( 101 ), where the combustion chamber operates at a pressure of 5 to 15 bara, and one or more heat exchanger(s) ( 107, 108 ) are provided for cooling of the combustion gas in line ( 106 ), a contact device ( 113 ) where the cooled combustion gas is brought in countercurrent flow with a lean CO 2  absorbent to give a rich absorbent and a CO 2  depleted flue gas, withdrawal lines ( 114, 115 ) for withdrawal of rich absorbent and CO 2  depleted flue gas, respectively, from the contact device, the line ( 115 ) for withdrawal of CO 2  depleted flue gas being connected to the heat exchangers ( 107, 108 ) for heating of the CO 2  depleted flue gas, and where the rich absorbent is regenerated an absorbent regenerator ( 116 ), the regenerated lean absorbent is recycled to the absorber ( 113 ), and a gas withdrawal line ( 121 ) connected to the absorber for withdrawal of CO 2  and steam from the regenerator ( 116 ), is described

CROSS-REFERENCE TO RELATED APPLICATION

This application is a Continuation of U.S. application Ser. No.12/833,570, filed on Jul. 9, 2010, which claims priority under 35 U.S.C.§119(a) on Patent Application No. 2009 2625, filed in Norway on Jul. 11,2009, the contents of each are hereby expressly incorporated byreference into the present application.

TECHNICAL FIELD

The present invention relates to a method and a plant for oil sandrecovery, heavy oil upgrading and power production with significantlyreduced CO₂ emission compared to the solutions according to the state ofthe art.

BACKGROUND

The global oil demand is increasing at the same time as easilyrecoverable oil resources become are recovered. Oil sand is a resourcethat has been exploited for some time but exploitation of this resourcehas negative environmental aspects in addition to be relativelyexpensive.

Oil sands, also known as tar sands or extra heavy oil, are a kind ofbitumen deposit that is found in a mixture of sand and/or clay, andwater. Recovering, processing and upgrading of the mixture to obtaincommercial oil are energy demanding and result in high CO₂ emission.This has caused environmental concerns related to this exploitation.

Oil sand is recovered either by opencast mining, or by drilling into anoil and field and withdrawing the bitumen from the sub terrainstructure. The choice of method depends on several factors, such as theactual structure and availability of the field. Recovering of bitumenfrom oil sand in a sub terrain structure by drilling into the structureand recovering the bitumen through oil wells, normally requires heatingof the structure as the viscosity of the bitumen at the temperatures inthe structures requires measures for lowering the viscosity such asheating or solvent extraction.

Known methods for heating of an oil sand reservoir are:

-   Toe to heel air injection, where air is injected into an injection    well, the bitumen is ignited to create a vertical wall of fire    driving the lighter components of the bitumen towards a production    well.-   Cyclic steam stimulation, wherein steam at 300 to 340° C. is    injected into a well, or a plurality of wells, for a period of weeks    to months to elevate the temperature in the structure. After    allowing the well to sit for some days to weeks, oil is produced.    When the production falls below a set limit, the steam injection is    started again.-   Steam assisted gravity drainage, wherein groups of horizontal wells    are drilled in the oil sands, a first group is drilled at the bottom    of the formation and the second group about 5 meter above the first.    Steam is injected into the second group of wells, melting the    bitumen that flows to the first group of wells and pumped to the    surface.-   Electro thermal stimulation (see e.g. U.S. Pat. No. 6,596,142),    wherein a plurality of electrodes is inserted into the reservoir and    the reservoir is heated electrically and heat is transferred within    the reservoir by means of convection and conduction. The melted    bitumen is then allowed to flow into production wells and is pumped    to the surface. Preferably, water is injected simultaneously with    the heating to further increase the production from the well.-   Additionally, a method combining injection of steam with electrical    heating of a reservoir is known from WO2007050445.

The toe to heel method is hard to control and is not suitable for allformations. Additionally, the combustion produces and emits CO₂ to thesurroundings.

The methods for heating the formation are all energy consuming methods,where natural gas, oil and/or coal are combusted to produce steam and/orelectrical power, an activity that causes CO₂ emission from theproduction of oil at an unacceptable high level. In many jurisdictionsimport of oil produced from oil sands is prohibited of this reason andit expected that laws and regulations in this regard will be introducedin many countries around the world due to the effect of CO₂ on thegreenhouse effect.

SUMMARY OF THE INVENTION

According to a first aspect, the present invention relates to a plantfor generation of steam for oil sand recovery from carbonaceous fuelwith capture of CO₂ from the exhaust gas, the plant comprising fuelline(s) for introduction of the fuel into a combustion chamber, airlines for introduction of air or another oxygen containing gas into thecombustion chamber, heat coils arranged in the combustion chamber (101)to cool the combustion gases in the combustion chamber to produce steamand superheated steam in the heat coils, steam withdrawal lines forwithdrawing steam from the heat coils, an exhaust gas line forwithdrawal of exhaust gas from the combustion chamber, wherein the plantadditionally comprises one or more compressors (to compress the air oroxygen containing gas to be introduced into the combustion chamberoperating at a pressure of 5 to 15 bara, one or more heat exchanger(s)for cooling of the combustion gas in line, a contact device where thecooled combustion gas is brought in countercurrent flow with a lean CO₂absorbent to give a rich absorbent and a CO₂ depleted flue gas,withdrawal lines for withdrawal of rich absorbent and CO₂ depleted fluegas, respectively, from the contact device, the line for withdrawal ofCO₂ depleted flue gas being connected to the heat exchangers (107, 108)for heating of the CO₂ depleted flue gas, one or more turbine(s) forexpanding the CO₂ depleted flue gas after heating, a flue gas line forreleasing the expanded and CO₂ depleted flue gas into the surroundings,an absorbent regenerator wherein the rich absorbent is regenerated, alean absorbent line for recycling of regenerated absorbent to theabsorber (113), and a gas withdrawal line connected to the absorber forwithdrawal of CO₂ and steam from the regenerator, and a steam line forintroduction of stream into an oil sands reservoir.

According to a first embodiment, one or more heat exchanger(s) is (are)arranged on steam lines, where a water line is arranged to introducewater into the heat exchanger, and the steam line is arranged towithdraw steam from the heat exchanger.

According to a second embodiment, one or more steam turbines is (are)arranged or expanding steam from lines to generate electrical power.

According to a third embodiment, the plant additionally comprises aheavy oil upgrade facility for upgrading the produced heavy oil from theoil sands.

According to a fourth embodiment, the plant additionally comprises agasifier for gasification of coal, a char line for withdrawing producedchar, a gas withdrawal line for withdrawal of produced gas in thegasifier, the gas withdrawal line being connected to a separator forseparation of the gasified products, a heavy hydrocarbons line forwithdrawal of a heavy hydrocarbon fraction of the gasified products, agas line for withdrawal of a gas mainly comprising methane and CO, and ahydrogen line for withdrawing hydrogen from the separator andintroducing the hydrogen into the upgrade facility.

According to a fifth embodiment, the plant additionally comprises a charand gas fired power plant for producing heat and electrical power, theplant comprising an exhaust gas line for withdrawal of exhaust gas fromthe power plant and for introducing the exhaust gas as an oxygencontaining gas into a power plant with CO₂ abatement.

According a sixth embodiment, wherein the exhaust gas line is connectedto an additional gas fired, power plant with CO₂ capture forintroduction of the exhaust gas as an oxygen containing gas into thepower plant.

According to a second aspect, the present invention relates to a systemfor producing oil from an oil sands field, where vapor injection wells,production wells and electrodes are provided in the oil gas field,wherein the system includes a plant as described above.

SHORT DESCRIPTION OF THE FIGURES

FIG. 1 is an exemplary flow diagram for a plant according to theinvention,

FIG. 2 is a flow diagram illustrating a power plant part of a plantaccording to FIG. 1,

FIG. 3 is an illustration of an alternative embodiment of the powerplant part as illustrated in FIG. 2,

FIG. 4 is a second alternative embodiment of the power plant part asillustrated in FIG. 2,

FIG. 5 is a flow diagram of an alternative embodiment of the plantaccording to the present invention, and

FIG. 6 is a second alternative embodiment of the plant according to thepresent invention.

DETAILED DESCRIPTION OF THE INVENTION

FIG. 1 is an illustration of a plant according to the present invention.

A power plant 10, preferably a plant with CO₂ abatement substantiallyaccording to WO2004001301 to Sargas A S, is provided for production ofelectricity, steam and to provide heat for heat consuming processes.FIG. 2 is a simplified view of the power plant of this type.

The power plant 10 may be fired by any suitable carbonaceous fuel, suchas coal, natural gas or oil, or any combination thereof dependent on thelocal price and availability thereof. Coal is introduced into the powerplant 10 through a coal line 11, 11′. The coal is grinded and mixed withwater and optionally with oil sand that is introduced through an oilsand line 15, into a slurry that is pumped into a pressurized combustionchamber 101 and combusted, preferably in a pressurized fluidized bedtogether with air. The air is introduced through an air intake 102 andis compressed by means of one or more compressor(s) 103, 103′ before itis introduced into the combustion chamber through an air line 104. Thecoal may be substituted or supplemented by natural gas introduced troughline 5, 5′.

The temperature in the combustion chamber reduced by means of productionof steam and superheating of steam in tube bundles 105, 105′, 105″respectively that are arranged in the combustion chamber 101.

Combustion gas from the combustion chamber 101 is withdrawn through anexhaust gas line 106 and is cooled in heat exchangers 107, 108 andoptionally by one or more coolers 109. Condenced water in the cooledcombustion gas is removed in a flash tank 110 and withdrawn through awater line 111.

The cooled exhaust gas leaving the flash tank 110 is withdrawn trough aline 112 from which it is introduced into an absorber 113 and is causedto flow countercurrent to a liquid CO₂ absorbent, to give a rich CO₂absorbent that is loaded with CO₂ that is withdrawn through an absorberexit line 114, and a CO₂ depleted exhaust gas that is withdrawn througha flue gas line 115.

The rich absorbent in line 114 is introduced into a regenerator column116 where it is caused to flow countercurrent with steam generated in areboiler 117 by boiling a part of the lean, or low CO₂ absorbent, thatis withdrawn from the bottom of the regenerator in a lean absorbentwithdrawal line 118. Lean absorbent is withdrawn from the bottom of theregeneration column in a line 120 and is recycled to the absorber 113. Aheat exchanger 119 is preferably provided to cool the lean absorbent inline 120 against rich absorbent in line 114 before the rich absorbent isintroduced into the regeneration column.

Released CO₂ and water vapor are withdrawn from the regeneration columnthrough a gas withdrawal line 121. The gas in the gas withdrawal line121 is cooled by a cooler 122 and gas and water is separated in aseparation tank 123, where water is collected in the bottom of the tankand withdrawn through a line 124 to be reintroduced into the process,e.g. as indicated in the figure by introduction of the water in theregeneration column to maintain the water balance in the system. The gasphase in the separation tank 123, being partly dried CO₂, is withdrawnthrough a gas line 125 and is further treated, mainly by compression andcooling as indicated with compressor 126 and cooler 127. Cooled andcompressed CO₂ is exported from the power plant 10 through a CO₂ line12′, 12 to be exported from the plant for deposition or enhanced oilrecovery (EOR).

Water from line 111 is preferably inserted into the CO₂ depleted fluegas withdrawn through line 115, and the gas is reheated in heatexchangers 108, 107 against the incoming exhaust gas in line 106. Thereheated CO₂ depleted flue gas is expanded over one or more turbines130, 139′ before the expanded gas is released into the surroundingsthrough a outlet line 131. The turbine(s) 130, 130′ may be arranged tooperate the compressors 130, 130′ and may additionally, oralternatively, be connected to a generator for production of electricalpower.

Water is introduced through a water injection line into tube bundle 105in the combustion chamber 101 to produce steam that is withdrawn througha steam line 133 and is expanded over a turbine 134. The expanded steamfrom turbine 134 is withdrawn through a line 135 and is introduced intothe tube bundle 105 where the steam in line 135 is heated to producesuperheated steam that is withdrawn through superheated steam line 136and introduced into and expanded in a turbine 137.

Expanded steam from the turbine 137 is withdrawn through a steam line138 and is introduced into a low pressure turbine 139 and expandedtherein. The turbines 134, 137 and 139 may be arranged on a common shaft140 to produce electrical power in a generator 141 arranged at the sameshaft. The electrical power produced in generator 141 and any otherelectrical power generated in the power plant 10, is exported from thepower plant 10 through line 2, 2′ as will be described below.

Tube bundle 105″ is connected to a steam cycle 145 into which steam iswithdrawn and introduced into a heat exchanger 142. Water is introducedinto heat exchanger 142 through a water inlet line 143. The introducedwater Is vaporized in heat exchanger 142 against the steam in the steamcycle 145, and the produced steam in the heat exchanger 142 is withdrawnthrough steam line 14, as described with reference to FIG. 1. The cooledsteam/condensed water in steam cycle 145 is then reintroduced into thetube bundle 105″. It would be possible to introduce water from line 143directly into the tube bundle 105″ to avoid the steam cycle 145 and theheat exchanger 142 and connect line 14 directly to the tube bundle 105″.The requirements for purity of the water to be introduced into a tubebundle in a boiler are, however, strong to avoid depositions andcorrosion in the tubes. An indirect heating system comprising a closedcycle of water/steam connected to a heat exchanger is thereforepreferred.

Depending on the relative requirement for electrical power and steam forEOR, the tube coils 105, 105′ and 105″ may be dimensioned or operated tomeet different needs. In a first embodiment illustrated in FIG. 2, steamand superheated steam are produced in tube coils 105, 105′,respectively, which steam is expanded over steam turbines 134, 137, 139for generation of power as described above. Steam EOR is generated asdescribed above by steam generation in the tube coil 105″ for heating ofwater and generation of steam in the heat exchanger 142. Steam for EORis withdrawn through line 14.

In a second embodiment, illustrated in FIG. 3, tube bundles 105, 105′are omitted and substituted totally by tube bundle 105″ so that allsteam production in the boiler is produced in tube coils 105″ and isused for EOR.

FIG. 4 illustrates a third embodiment, wherein tube coil 105′ isomitted. Both tube coils 105 and 105″ may be dimensioned individually tocool the combustion gases in the combustion chamber to the requiredtemperature, so that the plant may be operated in different modes, anormal mode where both electrical power and steam for EOR are produced,and alternative modes where all steam generated in the tube coils areproduced in either tube coils 105 or 105″, to result in production ofelectrical power only or steam for EOR only.

Any electrical power generated by the power plant 10 is withdrawnthrough lines 2′, 2 to be used in the plant 1 or to be exported. Theelectrical power in line 2 may be used as a supplement of alternative tosteam injection to promote production of bitumen, by means of electrodesinserted into the oil sand field.

Low temperature heat from the power plant, e.g. from any of the coolerssuch as a cooler 144 provided in line 132, may be withdrawn through aline 16 and be used in a heat exchanger 17 for heating the incomingbitumen in line 1 to reduce the viscosity thereof. The skilled man inthe art will, however, understand that heat from several coolers may becombined in line 16. Water return from the heat exchanger is withdrawnin a line 18 back to the power plant 10, e.g. via a gasifier 20, wherethe remaining heat in the water may be used to preheat incoming coal tobe gasified, before the water is returned to the power plant 10 via aline 19.

The gasifier 20 is provided to gasify coal. Coal is introduced into thegasifier 20 through the coal line 11, 11″ and as mentioned above, theincoming coal may be preheated by means of steam or water return fromheat exchangers. Gas is introduced into the gasifier to heat the coal ina gasifying reactor to a temperature typically above 700° C. Differentprocesses may occur in the gasifier:

-   Pyrolysis (or devolatization), that occurs as a result of the    heating of coal particles. During pyrolysis volatiles in form of    heavy hydrocarbons (HC), hydrogen and lighter hydrocarbons, mostly    methane, are released to leave char as a solid. The volatiles may    constitute up to 70% of the coal weight.-   Gasification by reaction with water to produce hydrogen and carbon    monoxide according to the reaction C+H₂O->H₂+CO.-   Water shift reaction, being a reversible reaction that may increase    the hydrogen production according to the following reaction    CO+H₂O←→CO₂+H₂.    Additionally, partial combustion by addition of a controlled amount    of oxygen may be included to provide heat for the gasification    process.

Water may be introduced into the gasifier 20 through a water line 21 toincrease the production of hydrogen in the gasifier if required orpreferred.

Char from the gasifier is withdrawn trough a char line 22. The volatilesare removed through a volatile line 23 and are introduced into aseparator 24. In the separator 24 heavy hydrocarbons (HC) are separatedfrom the remaining volatiles by condensation and are withdrawn trough aHC line 25. Hydrogen is separated from the remaining gaseous phase inthe separator 24 by means of any convenient separation technology, suchas membranes or pressure swing separation. Hydrogen is withdrawn througha hydrogen line 26, and delivered to the upgrade facility 30, whereasthe remaining gaseous phase, mainly comprising methane and CO, iswithdrawn through a gas line 27.

The steam in the above mentioned line 14 is introduced into a not shownoil sand reservoir to produce bitumen from the reservoir. The producedbitumen is withdrawn from the reservoir through the bitumen line 1, andoptionally heated in the heat exchanger 17 before the bitumen isintroduced into an upgrade facility 30.

In the upgrade facility, the bitumen is treated in a conventional way byremoval of water, sand, physical waste and lighter products, catalyticpurification for removal of metals, nitrogen and sulfur, and cracking,or cutting, of long hydrocarbon chains to produce shorter hydrocarbonchains to reduce the viscosity of the resulting mixture of hydrocarbonssubstantially.

Metals, sulfur and nitrogen that are bound to hydrocarbons in thebitumen are removed by hydrogenation processes. Removal of sulfur andnitrogen is typically performed in a reactor in the presence of a metalcatalyst at an elevated temperature, such as e.g. 300 to 400° C. and atan elevated pressure, such as from 30 to 130 bara, to produce adesulfurized and/or denitrogenified hydrocarbon product and H₂S and/orNH₃ that are separated from the product.

Heavy hydrocarbons are cracked, or cut in shorter hydrocarbon chains, byhydrocracking that is a catalytic cracking process at an elevatedpressure of hydrogen, to give lighter, and substantially saturatedhydrocarbons that are suitable for the demand for gasoline, diesel,kerosene etc.

Hydrogen for the upgrading facility is added to the upgrade facilitythrough the hydrogen line 26. An additional hydrogen line 33 receivinghydrogen from an electrolytic unit 32, may be provided if additionalhydrogen is needed. The electrolytic unit 32 splits water introducedthrough a water line 34 electrolytic by means of electrical powerreceived through a power line 2″ receiving power from the line 2.Hydrogen is withdrawn through line 33 and is introduced into the upgradefacility, whereas oxygen is withdrawn through an oxygen line 36.

Heat for the upgrading of the bitumen is received through, preferably inthe form of steam, in a line 37. The steam in line 37 is generated in apower plant 40 fired primarily by higher hydrocarbons leaving theupgrade facility in line 31, coke generated in the gasifier 20 and thatis carried in line 22 from the gasifier to the power plant 40, andhigher hydrocarbons in line 27 that are separated from the volatiles inthe separator 24.

The oil resulting from the upgrading of bitumen is withdrawn from theplant through a product line 3 for export from the plant.

The power plant 40 is thermal power plant that can combust coke, andhigher hydrocarbons to produce steam that is withdrawn through line 37,and electrical power that is withdrawn through line 2′″ and delivered toline 2 of use in the plant or to be exported. Air is introduced into thepower plant 40 through an air line 43.

Exhaust gas from the power plant 40 is withdrawn through en exhaust line41 and is mixed with air in an air line 42, and optionally with oxygenfrom line 36, before being introduced into a power plant 50 with CO₂abatement as oxygen containing gas. The power plant 50 is preferably aplant substantially as described with reference to FIG. 2. The fuel intothe power plant 50 is mainly methane and CO from the separator 24through line 25 and natural introduced through line 5′″, both into thecombustion chamber 101. CO₂ is withdrawn through line 12″ and iscombined with the CO₂ in line 12 for deposition or EOR. CO₂ depleted andexpanded flue gas, is released into the surroundings through a flue gasline 51, whereas electrical power is withdrawn through line 52 andcombined with the electrical power in line 2′″, 2.

Electrical power in line 2 is used for different purposes in the plant,for promoting production of bitumen and surplus electrical power may bedelivered to the grid 9 via a transformer 8.

FIG. 5 illustrates an alternative embodiment of the present inventionwhere power plants 10 and 50 are combined in one power plant 10. Exhaustline 41 from the power plant 40, and oxygen line 36 are here arranged todeliver the exhaust gas from the power plant 40 and oxygen from theelectrolysis unit 32, respectively, to the power plant 10 to be combinedwith air introduced through air intake 102, as oxygen containing gas forthe combustion in the combustion chamber 101. In this embodiment,natural gas constitutes all or most of the fuel for the power plant 10.Additionally, power plant 10 must be dimensioned to handle the capacityof both power plant 10 and 50.

FIG. 6 illustrates yet an alternative embodiment of the present plantincluding one power plant 10 with CO₂ capture, a gasifier 20 and anupgrade facility 20. In this embodiment the gasifier is operated so thatthe carbon in coal is gasified by the formula C+H₂O→CO+H₂. The generatedhydrogen may again react with additional water according to the abovementioned water gas shift reaction to give CO₂ and additional hydrogen.The energy need of the reactions in the gasifier may be solved byintroduction of some oxygen containing gas, resulting in a partialoxidation of carbon in an exothermal reaction.

When the gasifier is operated to give only gaseous products there is noneed for a char fired power plant. Any heat demand in any part of theplant may be solved by heat integration i.e. transferring heat from alocation where cooling is needed to heat a heat demanding part of theplant, or to take a part of the steam in line 14 and introduce thissteam into a heat demanding process.

Hydrogen from the separation unit 24 is introduced into the upgradefacility as described above, and the remaining gas from the separationunit is withdrawn through lines 27, 25, respectively, and introducedinto power plant 10 as fuel gas, together with heavy hydrocarbonswithdrawn from the upgrade facility through line 31.

1. A plant for generation of steam for oil sand recovery fromcarbonaceous fuel with capture of CO₂ from the exhaust gas, the plantcomprising: at least one fuel line for introduction of the fuel into acombustion chamber; at least one air line for introduction of air oranother oxygen containing gas into the combustion chamber; at least oneheat coil arranged in the combustion chamber to cool the combustiongases in the combustion chamber to produce steam and superheated steamin the heat coils; steam withdrawal lines for withdrawing steam from theheat coils; an exhaust gas line for withdrawal of exhaust gas from thecombustion chamber; one or more compressors to compress the air oroxygen containing gas to be introduced into the combustion chamberoperating at a pressure of 5 to 15 bara; one or more heat exchangers forcooling of the combustion gas in the exhaust gas line; a contact devicewhere the cooled combustion gas is brought in countercurrent flow with alean CO₂ absorbent to give a rich absorbent and a CO₂ depleted flue gas;withdrawal lines for withdrawal of rich absorbent and CO₂ depleted fluegas, respectively, from the contact device, the line for withdrawal ofCO₂ depleted flue gas being connected to the heat exchangers for heatingof the CO₂ depleted flue gas; one or more turbines for expanding the CO₂depleted flue gas after heating; a flue gas line for releasing theexpanded and CO₂ depleted flue gas into the surroundings; an absorbentregenerator wherein the rich absorbent is regenerated; a lean absorbentline for recycling of regenerated absorbent to the absorber; a gaswithdrawal line connected to the absorber for withdrawal of CO₂ andsteam from the regenerator; and a steam line for introduction of steaminto an oil sands reservoir.
 2. The plant according to claim 1, whereinone or more heat exchangers are arranged on the steam withdrawal lines,where a water line is arranged to introduce water into the one or moreheat exchangers arranged on the steam withdrawal lines, and the steamline for introduction of steam into an oil sands reservoir is arrangedto withdraw steam from the one or more heat exchangers arranged on thesteam withdrawal lines.
 3. The plant according to claim 1, wherein oneor more steam turbines are arranged for expanding steam from the steamwithdrawal lines to generate electrical power.
 4. The plant according toclaim 1, further comprising a heavy oil upgrade facility for upgradingthe produced heavy oil from the oil sands.
 5. The plant according toclaim 4, further comprising: a gasifier for gasification of coal; a charline for withdrawing produced char; a gas withdrawal line for withdrawalof produced gas in the gasifier, the gas withdrawal line being connectedto a separator for separation of the gasified products; a heavyhydrocarbons line for withdrawal of a heavy hydrocarbon fraction of thegasified products; a gas line for withdrawal of a gas mainly comprisingmethane and CO; and a hydrogen line for withdrawing hydrogen from theseparator and introducing the hydrogen into the upgrade facility.
 6. Theplant according to claim 5, further comprising: a char and gas firedpower plant for producing heat and electrical power; and an exhaust gasline for withdrawal of exhaust gas from the power plant and forintroducing the exhaust gas as an oxygen containing gas into a powerplant with CO₂ abatement.
 7. The plant according to claim 6, wherein theexhaust gas line is connected to an additional gas fired, power plantwith CO₂ capture for introduction of the exhaust gas as an oxygencontaining gas into the power plant.
 8. A system for producing oil froman oil sands field, where vapor injection wells, production wells andelectrodes are provided in the oil gas field, wherein the systemcomprises a plant according to claim
 1. 9. The plant according to claim2, wherein one or more steam turbines are arranged for expanding steamfrom the steam withdrawal lines to generate electrical power.
 10. Theplant according to claim 2, further comprising a heavy oil upgradefacility for upgrading the produced heavy oil from the oil sands. 11.The plant according to claim 3, further comprising a heavy oil upgradefacility for upgrading the produced heavy oil from the oil sands. 12.The plant according to claim 11, further comprising: a gasifier forgasification of coal; a char line for withdrawing produced char; a gaswithdrawal line for withdrawal of produced gas in the gasifier, the gaswithdrawal line being connected to a separator for separation of thegasified products; a heavy hydrocarbons line for withdrawal of a heavyhydrocarbon fraction of the gasified products; a gas line for withdrawalof a gas mainly comprising methane and CO; and a hydrogen line forwithdrawing hydrogen from the separator and introducing the hydrogeninto the upgrade facility.
 13. The plant according to claim 12, furthercomprising: a char and gas fired power plant for producing heat andelectrical power; and an exhaust gas line for withdrawal of exhaust gasfrom the power plant and for introducing the exhaust gas as an oxygencontaining gas into a power plant with CO₂ abatement.
 14. The plantaccording to claim 13, wherein the exhaust gas line is connected to anadditional gas fired, power plant with CO₂ capture for introduction ofthe exhaust gas as an oxygen containing gas into the power plant.